Apparatus and process for treating natural gas

ABSTRACT

A process is described for treating a natural gas stream containing methane and one or more higher hydrocarbons including the steps of mixing at least a portion of the natural gas stream with steam; passing the mixture adiabatically over a supported precious metal reforming catalyst to generate a reformed gas mixture comprising methane, steam, carbon dioxide, carbon monoxide and hydrogen; cooling the reformed gas mixture to below the dew point to condense water and removing the condensate to provide a de-watered reformed gas mixture, and passing the de-watered reformed gas mixture through an acid gas recovery unit to remove carbon dioxide and at least a portion of the hydrogen and carbon monoxide, thereby generating a methane stream. The methane stream may be used to adjust the composition of a natural gas stream, including a vaporized LNG stream, to meet pipeline specifications.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. application Ser.No. 13/520,442, filed Dec. 21, 2012 which is the U.S. National Phaseapplication of PCT International Application No. PCT/GB2010/052115,filed Dec. 16, 2010, and claims priority of British Patent ApplicationNo. 1000097.4, filed Jan. 5, 2010, the disclosures of which areincorporated herein by reference in their entireties for all purposes.

FIELD OF THE INVENTION

This invention relates to a process for treating natural gas to removehigher hydrocarbons present therein to make it more suitable forliquefied natural gas (LNG) production or to adjust its composition tomeet pipeline specifications.

BACKGROUND OF THE INVENTION

Natural gas, comprising methane and higher hydrocarbons such as ethane,propane and butane, is often recovered directly, or as an associated gaswith oil production, offshore using fixed or floating platforms coupledto well heads on the seabed. The recovered natural gas is, wheregenerally possible, fed via pipeline to on-shore gas processingfacilities where such steps as purification may be carried out. For asignificant proportion of the recovered natural gas, pipelining toon-shore facilities is not possible. In such cases it has becomedesirable to recover and liquefy the natural gas for sea transportationto on-shore facilities. Similarly, on-shore stranded natural gas isincreasingly liquefied for transportation to overseas markets. Theliquefaction processes typically include steps of cooling the naturalgas to a very low temperature, which allows separation of at least someof the ethane, propane, butanes and other higher hydrocarbons from themethane. The liquefied products have different commercial values, butwhere further processing such as cracking is not feasible, typically theethane has the lowest value, and so part is often used for powergeneration in the liquefaction facility and the excess is flared.Alternatively, in off shore production, the excess ethane may berecovered and transported alongside the LNG to the onshore facility.However the economics of transporting ethane in place of the morevaluable liquids is less attractive. With ever-increasing pressure onmaximising the utilisation of the recovered hydrocarbons coupled with aneed to reduce flaring, which has become environmentally unsound, thereis a need for an improved process for treating natural gas containinghigher hydrocarbons.

Furthermore, so-called “rich” natural gas streams containing relativelylarge amounts of higher hydrocarbons, whether recovered directly or byvapourisation of rich-LNG's, often pose a problem for the processorrequired to meet pipeline specifications on their content and calorificvalue.

GB2432369 discloses a method of treating natural gas containing ethanebased on the CRG process, developed originally by British Gas andlicensed by Davy Process Technology Ltd. The method utilises acombination of adiabatic steam reforming over a nickel catalyst attemperatures in excess of 350° C., methanation and CO₂ removal on ethaneextracted from the natural gas to generate methane, which is mixed withthe natural gas, which may be liquefied.

This process has a number of drawbacks including the need to separateethane and higher hydrocarbons as well as the methanation step, which isrequired to convert the carbon monoxide and hydrogen formed over thenickel catalyst back into methane.

Other processes are known for adjusting the calorific value of richnatural gases but these require the use of ballasting agents such asnitrogen, which has to be separately generated and stored.

SUMMARY OF THE INVENTION

We have developed a process that utilises the higher hydrocarbons in thenatural gas to make methane and overcomes the problems of the previousnatural gas treatment processes.

Accordingly the invention provides a process for treating a natural gasstream containing methane and one or more higher hydrocarbons comprisingthe steps of:

-   (i) mixing at least a portion of the natural gas stream with steam,-   (ii) passing the mixture adiabatically over a supported precious    metal reforming catalyst at an inlet temperature in the range    130-300° C. to generate a reformed gas mixture comprising methane,    steam, carbon dioxide, carbon monoxide and hydrogen,-   (iii) cooling the reformed gas mixture to below the dew point to    condense water and removing the condensate to provide a de-watered    reformed gas mixture, and-   (iv) passing the de-watered reformed gas mixture through an acid gas    recovery unit to remove carbon dioxide and at least a portion of the    hydrogen and carbon monoxide, thereby generating a methane stream.

The methane stream may be used as a fuel or liquefied for transportationor storage. Alternatively the methane stream may be used to adjust thecomposition of a natural gas stream, including a vapourised LNG stream,to meet pipeline specifications.

By “higher hydrocarbons” we include one or more of ethane, propane,butanes and any C5+ paraffins, cycloalkanes such as cyclohexane, andaromatic hydrocarbons such as benzene.

By using a precious metal reforming catalyst, it is possible to includemethane in the reformer feed, reduce the size of the reformer vessel andoperate under conditions that remove the need for a methanation step. Asa consequence, the weight is reduced and the footprint of the process issmaller which is particularly advantageous for off-shore operation ofthe process.

Accordingly the invention further provides apparatus for treating anatural gas stream containing methane and one or more higherhydrocarbons comprising:

-   (i) means for adding steam to a natural gas stream,-   (ii) a reformer vessel operatively connected to the means for adding    steam, said reformer vessel containing a supported precious metal    reforming catalyst, configured such that the mixed natural gas    stream and steam are passed over the catalyst to generate a reformed    gas mixture comprising methane, steam, carbon dioxide, carbon    monoxide and hydrogen,-   (iii) heat exchange means operatively connected to the reformer    vessel to cool the reformed gas mixture to below the dew point and    separation equipment operatively connected to the heat exchange    means to recover process condensate and provide a de-watered    reformed gas mixture, and-   (iv) an acid gas recovery unit operatively connected to the    separation equipment to remove carbon dioxide and at least a portion    of the hydrogen and carbon monoxide, thereby generating a methane    stream.

The apparatus may further comprise natural gas liquefaction equipmentoperatively connected to the acid gas recovery unit to liquefy at leasta portion of the methane stream. Alternatively or additionally theapparatus may further comprise mixing apparatus to combine the methanestream with a natural gas stream and/or higher hydrocarbon stream.

The process may be operated on-shore to overcome problems in existingrich natural gas liquefaction plants or may be used at LNG receivingterminals in re-gasification plants to adjust the composition of thevapourised LNG.

In a preferred embodiment the process is operated on an offshore naturalgas processing facility. In this embodiment, natural gas is recoveredand provided to an offshore natural gas processing facility usingconventional recovery techniques and pipeline equipment. Preferably, theoffshore natural gas processing facility is a fixed offshore facility ora floating offshore facility such as a floating liquefied natural gasproduction facility.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is further illustrated by reference to the figures inwhich;

FIG. 1 depicts an arrangement of unit operations for a first embodimentof the present invention on an a floating liquid natural gas-productionunit configured to process a rich natural gas into a LNG stream,

FIG. 2 is a flowsheet depicting a process according to the firstembodiment,

FIG. 3 is a flowsheet depicting a process according to a secondembodiment configured to process a rich-LNG stream into a methanestream,

FIG. 4 is a flowsheet depicting a process according to a thirdembodiment configured to convert a rich natural gas into a LNG streamand one or more higher hydrocarbon streams, and

FIG. 5 is a flowsheet depicting a process according to a furtherembodiment configured to convert a rich natural gas into a LNG streamand one or more higher hydrocarbon streams.

DETAILED DESCRIPTION OF THE INVENTION

The natural gas stream treated according to the inventive method may bea natural gas, including associated gas, recovered from on-shore oroff-shore reservoirs, or another gas mixture comprising methane and oneor more higher hydrocarbons. Thus, whereas the natural gas stream may benatural gas itself, it may alternatively be a synthetic natural gasmixture comprising a mixture of methane or natural gas and one or morehigher hydrocarbons that have been separated, e.g. by liquefaction,refrigeration or otherwise from a natural gas mixture. The natural gasstream may alternatively be a shale gas, tight sand gas or coal-bedmethane gas. As well as methane and higher hydrocarbons, the natural gasmay comprise carbon dioxide and/or nitrogen.

It is desirable that the amount of methane in the natural gas stream isin the range 5 to 99% by volume, preferably 25 to 95% more preferably 50to 95% by volume as this allows the use of a saturator to give thedesired steam:carbon ratio which overcomes the need for a separate steamdrum while at the same time enabling a sufficiently high amount ofhigher hydrocarbon to be reformed. Using a saturator advantageous interms of boiler fuel costs and in space, particularly where it isdesired to operate the process offshore and it conveniently allowsre-circulation of process condensate to the reforming step. Processcondensate may contain soluble or partly soluble hydrocarbons andreturning them to the reforming step is advantageous as a source of fueland to reduce the water treatment/purification burden of the process.

In a preferred embodiment, the process further comprises a step offeeding at least a portion of the methane stream to a natural gasliquefaction plant. In one such embodiment, all the recovered naturalgas is fed to the reforming process so that the natural gas liquefactionstep processes only methane to LNG and no liquefied higher hydrocarbons(i.e. natural gas liquids) are produced. Such a process offers aconsiderable advantage over the current processes where fractionationand storage/flaring of natural gas liquids, such as ethane, propane andbutane, are practised.

In an alternative embodiment, the reformer feed comprises a portion ofthe natural gas feed stream and the remaining portion is mixed witheither the de-watered reformed gas mixture fed to the acid gas removalunit, or, where the CO₂ and N₂ contents of the recovered natural gas arelow, directly with the methane stream itself. The portion of natural gasfed to the reformer in this case may be in the range 5-95% vol of theoriginal natural gas feed stream. The relative proportions will dependon the amount of higher hydrocarbon required to be converted to methane.The product gas stream in this case is a methane-enriched natural gasstream. The methane enriched natural gas will contain reduced amounts ofhigher hydrocarbons. The methane-enriched natural gas stream may betransported by pipeline to be used as a fuel for industrial or domesticpurposes or may be liquefied using conventional LNG liquefaction andfractionation equipment to provide a LNG stream and one or more higherhydrocarbon streams. By removing a portion of the higher hydrocarbonsfrom the feed to the liquefaction and fractionation plant, its size andoperating costs may be reduced. One or more of the higher hydrocarbonstreams separated in the liquefaction may be used as fuels or chemicalfeedstocks, or fed to the reformer as part of the natural gas stream.

In a further embodiment that includes a natural gas liquefaction step, anatural gas feedstock is mixed with the de-watered reformed gas mixtureand the resulting mixture fed to the acid gas recovery unit to generatea methane-enriched natural gas stream, a portion of which is mixed withone or more higher hydrocarbons to generate a synthetic natural gasstream for the reforming stage. The remaining portion of themethane-enriched natural gas stream is fed to a natural gas liquefactionand fractionation unit that separates higher hydrocarbons, one or moreof which are included in the natural gas stream fed to the reformer. Theportion of the methane-enriched natural gas forming the syntheticnatural gas stream fed to the reformer in this case may be in the range5-95% vol.

The process of the present invention is desirably operated at pressuresin the range 10-100 bar abs, preferably in the range 10-50 bar abs,which may be achieved by compression of the natural gas stream, wherenecessary.

The natural gas stream is desirably preheated prior to admixture withsteam and the reforming step using conventional means such as a firedheater, which may also be used to generate the steam subsequently mixedwith the natural gas stream, or by exchanging heat with the reformed gasmixture. The natural gas stream is desirably heated to a temperature inthe range 75-275° C., preferably 100-220° C. prior to mixing with steam.

Where the natural gas contains mercury, it may be desirable to include astep of purifying the natural gas to remove mercury. Removing mercuryprotects process operators and equipment. For example, removing mercuryupstream of liquefaction protects the heat exchangers, which are oftenfabricated from aluminium, from the corrosive effect of mercury. Thus,preferably, the process comprises passing the natural gas over a mercurysorbent disposed in a purification vessel. Desirably this unit isinstalled upstream of the means for adding steam in order to preventmercury from contaminating the reforming process. Suitable mercurysorbents include transition metal sulphides, particularly coppersulphide, mixed with various support materials in the form ofagglomerates. Such materials are commercially available from JohnsonMatthey PLC, for example as PURASPEC_(JM)™ 1163. Alternatively, atransition metal compound, e.g. copper hydroxycarbonate, may be providedin a suitable form to the unit and sulphided in-situ by sulphurcompounds present in the natural gas, thereby resulting in co-removal ofsulphur and mercury. The mercury removal step is preferably operatedbelow 150° C., more preferably below 100° C., and at pressures up toabout 200 bar abs, e.g. in the range 10-100 bar abs. Accordingly, amercury removal stage may be included before or after any stage ofheating the natural gas stream.

Where the natural gas contains sulphur compounds, it may be desirablethat the process further comprises a step purifying the natural gasstream to remove sulphur compounds upstream of the reforming step inorder to protect the reforming catalyst from the poisoning effect ofsulphur. Thus, the process may comprise the step of desulphurising thenatural gas stream by passing it over one or more desulphurisationmaterials disposed in a desulphuriser vessel. The desulphurisation ofthe natural gas stream is preferably carried out upstream of thereformer vessel, more preferably upstream of the means for adding steam.The sulphur compounds may include one or more of hydrogen sulphide(H₂S), carbonyl sulphide (COS), mercaptans, sulphides, and thiophenes.H₂S may simply be absorbed using one or more beds of sulphur absorbentsuch as a commercially available ZnO or a metal-promoted, e.g.Cu-promoted, ZnO/alumina composition, at temperatures in the range50-275° C. Where sulphur compounds other than hydrogen sulphide arepresent in high concentrations, it may be desirable to include a firststep of hydrodesulphurisation followed by a step of hydrogen sulphideabsorption. In this embodiment, the desulphurisation materials comprisea bed of hydrodesulphurisation catalyst located upstream of a bed ofhydrogen sulphide absorbent. In hydrodesulphurisation, the natural gasstream containing a small amount, e.g. 1-2% vol, of hydrogen are passedover a Ni- and/or Co-based catalyst that converts the organo-sulphurcompounds to hydrogen sulphide. Typical catalysts are alumina-supportedNi/Mo, Co/Mo, Ni/W, and Co/W catalysts. Such catalysts are availablecommercially. The hydrogen sulphide thus generated, in addition to anyhydrogen sulphide naturally present in the natural gas, may then beabsorbed by a suitable hydrogen sulphide absorbent, such as aZnO-material. Again, such absorbent materials are availablecommercially. The hydrodesulphurisation catalyst may also be effectivefor hydrogenating olefins and converting amines to ammonia. Thehydrodesulphurisation catalyst and hydrogen sulphide absorbent may be inthe same or different vessels. The combined hydrodesulphurisation andH₂S absorption is preferably operated above 150° C., more preferablyabove 200° C., and at pressures up to about 100 bar abs. Hydrogenrequired for hydrodesulphurisation may be provided from storage, aseparate hydrogen generator apparatus, or by recycling a portion of thede-watered reformed gas mixture.

Where the precious metal reforming catalyst is sulphur-resistant, thesulphur compounds, particularly hydrogen sulphide, may instead beremoved alongside carbon dioxide in the acid gas recovery unit using amembrane, a physical wash solvent or an aqueous amine.

The natural gas stream after any compression, heating and purificationstages is then mixed with steam. This may be by direct injection ofsteam from a conventional steam drum but is preferably by means of oneor more saturators. Alternatively a combination of direct steam additionand a saturator may be used. In a saturator, the natural gas stream iscontacted with a re-circulated stream of pressurised hot water attemperatures typically >160° C. In order to increase the efficiency, thesaturator desirably contains a packed bed of ceramic rings or othersuitable packing media. The steam:carbon ratio in the reformer feedshould be controlled to avoid carbon deposition on the catalyst. Oneadvantage of using precious metal reforming catalysts compared to nickelreforming catalysts, is their greater resistance to carbon formation atlow steam:carbon ratios. In addition, the lower thermal mass requiredwith precious metal catalysts also offers a faster start-up thanconventional nickel-catalysed reforming processes. Because, in thepresent invention, the methane is largely inert in the reforming stagethe steam:carbon ratio may be in the range 0.2 to 3:1, preferably in therange 1 to 2.5:1, based on the higher hydrocarbon carbon.

In a preferred embodiment, a portion of the steam mixed with the naturalgas stream is generated from at least a portion of the recoveredcondensate. Thus, preferably the separation equipment is operativelyconnected to the means for adding steam to the natural gas stream sothat at least a portion of the recovered condensate is used to generateat least a portion of the steam mixed with the natural gas stream.

A further source of water for steam reforming may be molecular sieve orglycol driers that can be used to dry the methane stream ormethane-enriched natural gas stream prior to liquefaction.

The temperature of the natural gas stream/steam mixture may becontrolled for example using the preheater and/or steam temperature, andis in the range 130-300° C., but is preferably 150-275° C., morepreferably 160-200° C., e.g. 200-220° C. at the inlet of the reformervessel.

The pressure of the natural gas/steam mixture fed to the reformingcatalyst is preferably in the range 10-100 bar abs.

Preferably, hydrogen is included, at least temporarily, in the reformerfeed at concentrations up to 5% vol, more preferably at concentrationsup to 3% vol, most preferably 1-2% vol. This may be achieved by feedinghydrogen to the natural gas stream and/or hydrocarbon/steam mixtureupstream of the reformer. Thus hydrogen may be added to the natural gasstream upstream of any hydrodesulphurisation or saturator and/or, ifdesired, added to the hydrocarbon steam mixture upstream of thereformer. The hydrogen may be sourced from bottled supplies or may begenerated electrolytically from water, or by steam reforming a separatednatural gas stream or a separated reformed gas stream using asmall-scale adiabatic reformer containing nickel catalysts. In thiscase, a minor portion of the purified hydrocarbon stream or reformed gasmixture, which comprise methane, may be mixed with steam and the mixtureheated in the fired heater and passed through the adiabatic steamreformer unit containing the catalyst at temperatures in the range350-500° C. to generate a reformed gas mixture containing sufficienthydrogen for the reformer feed stream. Alternatively or additionally, aportion of the reformed gas mixture, which contains a small amount ofhydrogen, may be re-circulated to the reformer.

The mixture comprising the natural gas stream and steam, and anyhydrogen, is passed to a reformer vessel containing a supported preciousmetal reforming catalyst. Reforming reactions take place adiabaticallyover the precious metal catalyst to convert the higher hydrocarbonspresent to methane with only a small amount of methane converted tocarbon oxides, hydrogen and steam. The reforming catalyst is a supportedprecious metal catalyst. Suitable catalysts comprise one or more of Pt,Pd, Ir, Rh or Ru, preferably Rh or Ru. Especially preferred catalystscomprise Ru, on a catalyst support, optionally with one or morepromoters. Ru catalysts, particularly promoted Ru catalysts, can operateat higher space velocities, lower steam ratios and lower temperaturesthan conventional Ni steam reforming catalysts. Precious metal loadingon the support may be in the range 0.1-10.0% wt, but is preferably0.5-5% by weight. The catalyst support may be any conventional catalystsupport suitable for operation in steam reformers such as alumina,calcium aluminate, magnesia, titania, zirconia or other refractory oxidematerials. As the reforming temperature is relatively low, high surfacearea supports may be advantageously used such as transition aluminasincluding gamma-, delta- or theta-aluminas. The reforming catalyst maybe in the form of shaped units such as rings or cylinders with one ormore through-holes and/or one or more flutes or grooves running alongthe length of the unit. Such shaped units offer high geometric surfaceareas combined with low pressure drop. Alternatively the catalyst may bein the form of a monolith, i.e. a honeycomb, formed from a metal orceramic substrate onto which a washcoat containing the precious metalhas been coated. Suitable catalysts may be prepared by conventionalmethods such as by impregnating the support with a soluble salt ofprecious metal or my preparing a washcoat containing a suitable preciousmetal compound and coating the support with the washcoat, followed bydrying calcination and, if desired, reduction of the metal to its activeform. Reduction of the metal may if desired be performed in-situ, inwhich case the catalyst may be provided in oxidic form.

Hence, the reforming step may be operated at a pressure in the range 10to 70 bar, preferably 10 to 50 bar, and an inlet temperature in therange 160 to 220° C., preferably 160-200° C., over a supported Rutheniumcatalyst.

The reformed gas mixture comprising methane and steam with some carbondioxide, carbon monoxide and hydrogen is then cooled using one or moreheat exchangers, which may advantageously be used to preheat the steamused in the reforming step and/or used to provide heat for the acid-gasrecovery unit where physical- and chemical-wash solvents are employed.The cooling is continued to below the dew point to condense the steam.

The cooled gas/condensate mixture is then passed to separation equipmentpreferably comprising one or more separators, more preferably withfurther cooling, to collect and recover process condensate. As statedabove, the process condensate is a valuable source of water and may beused to generate a portion of the steam that is mixed with the naturalgas stream. The gaseous product from the separation stage is ade-watered reformed gas mixture comprising methane with some carbondioxide and minor amounts of carbon monoxide and hydrogen. In order thatthe acid gas recovery unit is able to efficiently remove the reformingby-products, the de-watered reformed gas mixture preferably contains ≤5%vol, preferably ≤3% vol, more preferably ≤1% vol H₂. The CO content ofthe de-watered reformed gas is preferably ≤1% vol, preferably ≤0.5% vol,more preferably ≤0.1% vol. The CO₂ content of the de-watered reformedgas may be in the range 5-25% vol.

Carbon dioxide is undesirable in the methane product stream because itcan alter the calorific value of the natural gas and freezes above thenatural gas liquefaction temperatures. Therefore, the present inventionincludes a step of passing the de-watered reformed gas mixture, whichmay further comprise a portion of natural gas, through an acid gasrecovery unit (AGRU). Such AGRUs are currently used at the front end ofLNG plants. Acid-gas removal, may be accomplished using membranetechnology (e.g. based on anisotropic cellulose acetate, polylmide orperfluoropolymer membranes) or the known aqueous chemical wash (e.g.amine wash) or physical wash processes that use solvents such as coldmethanol, N-methyl pyrrolidone or propylene carbonate, or glycol ether.Where physical wash solvents are used, it is desirable to dry thedewatered reformed gas mixture before passing it to the AGRU usingconventional zeolite or glycol drying steps. Amine wash processes, whichare commercially available, are preferred.

The AGRU removes the carbon dioxide and at least a portion of the carbonmonoxide and hydrogen present in the de-watered reformed gas giving amethane stream, or where natural gas is mixed with the de-wateredreformed gas, a methane-enriched natural gas stream.

Where the acid gas recovery unit utilizes a solvent or amine wash,suitable protection means such as a sorbent bed are desirably provideddownstream to prevent contamination of downstream processes with thesefluids.

The product methane stream may be further dried and compressed forpipeline distribution using conventional equipment, or it may be mixedwith a natural gas stream and processed conventionally to provide a fuelfor domestic or industrial use.

In one embodiment of the present invention, at least a portion of themethane stream or methane-enriched natural gas stream is cooled andliquefied to generate a methane-enriched LNG. Higher hydrocarbonfractions so-produced may be commercialised as fuels or as chemicalfeedstocks or may be returned to the reforming process as part of thenatural gas stream.

Where the methane stream or methane-enriched natural gas stream is fedto a natural gas liquefaction plant, it is preferably subjected to oneor more drying stages to prevent any entrained water vapour fromfreezing in the liquefaction equipment. Furthermore, removal of watervapour is desirable in order to avoid the formation of hydrocarbonhydrates in the gas stream and also to avoid the water condensing out ofthe gas in pipelines and process equipment which may then lead tocorrosion problems. The drying step may be accomplished using knownmethods for drying natural gas mixtures, such as by contacting the gaswith a bed of a solid desiccant such as a silica gel or molecular sieve,or the use of liquid desiccant compounds, such as glycols. In order toreach the very low water levels required for efficient operation of theliquefaction unit, molecular sieve driers containing, e.g. zeolites, arepreferred. After drying, the dried methane stream or driedmethane-enriched natural gas stream may be passed to a liquefaction unitto generate a liquefied natural gas stream. The water recovered from themolecular sieve or glycol driers upon their regeneration may usefully befed to the process as a source of steam.

Where a methane-enriched natural gas is fed to a liquefaction process,it may be desirable to subject the natural gas, before it is mixed withthe methane stream, to one or more steps of mercury and/or sulphurcompound removal as described above to remove any mercury and sulphurcompounds that may be present to prevent contamination of the AGRU anddownstream equipment.

The liquefaction unit desirably comprises a natural gas liquefactionunit and optionally one or more fractionation columns depending upon thecomposition of the methane-containing stream. Preferably, the driedmethane stream or dried methane enriched natural gas stream is fed to aliquefaction unit where it is cooled firstly to between −20 and −40° C.before being fed to a first fractionation column where the heavyhydrocarbons are separated from a methane-rich stream. The lightfraction from the top of the column is further cooled and condensedliquids separated. Thus the higher hydrocarbons are liquefied. One ormore further columns may be used on the light and heavy fractions fromthe first column to obtain fractions rich in methane, ethane, propane,butanes and other hydrocarbons. Methods for processing the liquefiednatural gas streams in this way are described for example in U.S. Pat.No. 6,564,579.

Where the feed to the liquefaction unit consists of a methane stream, nofractionation to produce natural gas liquids is required.

Where the feed to the liquefaction unit comprises a methane-enrichednatural gas stream, desirably the liquefaction unit is operated suchthat a methane-enriched natural gas stream is separated into amethane-rich stream (i.e. a liquefied natural gas), an ethane stream, anLPG stream (containing propane and butanes) and a heavy stream.

The higher hydrocarbons that may be fed to the reforming step preferablycomprises ethane and optionally a portion of the LPG and/or a heavystream containing C5+ paraffins. Preferably >50% by volume,preferably >75%, more preferably >90% of the higher hydrocarbons fed tothe reforming step is ethane.

Ethane, propane butane and other higher hydrocarbons not used inreforming may be used to generate power for the process, e.g. using agas turbine.

The present invention, by converting the higher hydrocarbons to methane,provides a gas stream suitable for adjusting rich natural gascompositions to meet pipeline specifications and in particular, whencombined with natural gas liquefaction, overcomes the problem of flaringand/or storing & transporting higher hydrocarbons and increases LNGproduction. Removing or reducing LPG storage also improves the safety ofthe natural gas liquefaction and storage facility. Moreover, removinghigher hydrocarbons with relatively high melting points, particularlyC5+ hydrocarbons, overcomes problems such as blockages in theliquefaction plant caused by freezing and foaming in the acid gasremoval unit.

In FIG. 1 a floating LNG production unit 100 has mounted thereon andoperatively connected to each other a mercury removal unit 102 fed withnatural gas, a desulphurisation unit 104, a saturator 106 for addingsteam to the desulphurised natural gas, a reformer vessel 108, heatexchange and process condensate separation equipment 110, an acid gasremoval unit 112, a gas drying unit 114, and liquefaction equipment 116,that produces a liquefied natural gas stream 118 for storage in storagetanks 120. Process condensate recovered from the separation equipment110 is fed via line 122 to the saturator 106 to generate a portion ofthe steam.

In FIG. 2, a natural gas feed stream 200 is passed at a temperaturebelow 100° C. and a pressure of about 10 bar abs, to a firstpurification vessel 202 containing a particulate copper-sulphide basedmercury absorbent 204. Mercury and other heavy metals such as arsenicare absorbed by the absorbent. The resulting gas stream 206 is fedthough coils in a fired heater 208 fuelled by natural gas and/or higherhydrocarbon, where it is heated to a temperature about 110° C. Fromfired heater 208 the gas is passed via line 210 to a desulphuriservessel 212 containing a fixed bed of a particulate zinc oxidedesulphurisation absorbent 214 that removes hydrogen sulphide present inthe gas. The desulphurised natural gas stream is passed from thedesulphuriser vessel 212 via line 216, mixed with a hydrogen stream inline 217 and the mixture fed to a saturator 218 where it is contactedwith a stream of hot water/steam at a temperature about 190° C. at apressure about 10 bar abs. The saturated hydrocarbon/steam mixture isthen fed at a temperature about 180° C. via line 220 to the inlet of areformer vessel 222 containing a supported ruthenium steam reformingcatalyst 224. The steam reforming reactions take place adiabatically asthe hydrocarbon-steam mixture passes through the catalyst 224. The hotreformed gas mixture is cooled in a heat exchanger 226 and one or morefurther heat exchangers (not shown) to below the dew point to generate acondensate/gas mixture, which is fed via line 228 to a first separator230. The condensed liquids are recovered via line 232 and the gases fedvia line 234 to a water-cooled heat exchanger 236 where they are furthercooled, and then to a second separator 238. The remaining condensate isrecovered from the separator 238 via line 240 and combined with thecondensate stream 232 from the first separator.

The combined condensate streams are fed to a condensate stripper 242. Awater feed stream 244 from the condensate stripper is mixed with make-upboiler feed water 246 and the combined water fed to the heat exchanger226 where it is heated in indirect heat exchange with the reformed gasmixture. A heated water/steam stream 248 from the heat exchanger 226 iscombined with a pumped re-circulated hot water stream 250 from thesaturator 218 and the combined water/steam mixture is further heated bypassing it through coils in the fired heater 208. The heated water/steamstream is then fed to the saturator 218 from the fired heater 208 vialine 252.

The de-watered reformed gas mixture recovered from the second separator238 is fed via pump 254 to acid gas recovery unit (AGRU) 256. Theacid-gas removal unit 256 contains a membrane that separates CO₂, and atleast part of the hydrogen and CO from the gas stream. The CO₂-richstream is recovered from the AGRU via line 258 In an alternativeembodiment, the acid-gas removal step uses an amine wash unit thatremoves the CO₂ and some H₂S by contacting the gas with an aqueous aminesolution. In yet a further alternative embodiment, the acid-gas removalstep uses a physical wash solvent unit that removes the CO₂ and some H₂Sby contacting the gas with refrigerated methanol, glycol, N-methylpyrrolidone, or propylene carbonate.

The resulting methane gas stream is fed from the AGRU 256 via line 260to a drier vessel 262 where it contacts a zeolitic molecular sieve thatacts as a desiccant to remove water. The dried methane gas stream isthen cooled to between −20 and −40° C. in one or more heat exchangers264 to form a liquefied natural gas stream 266.

In FIG. 3, a liquefied natural gas feed stream 300 is passed throughvapouriser 302 to form a rich natural gas stream. The vapourised gasstream 306 is fed though coils in a fired heater 308 fuelled by naturalgas and/or higher hydrocarbon, where it is heated to a temperature about110° C. From fired heater 308 the gas is passed via line 310 to adesulphuriser vessel 312 containing a fixed bed of a particulate zincoxide desulphurisation absorbent 314 that removes hydrogen sulphidepresent in the gas. The desulphurised natural gas stream is passed fromthe desulphuriser vessel 312 vial line 316, mixed with a hydrogen streamin line 317 and the mixture fed to a saturator 318 where it is contactedwith a stream of hot water/steam at a temperature about 190° C. at apressure about 10 bar abs. The saturated hydrocarbon/steam mixture isthen fed at a temperature about 180° C. via line 320 to the inlet of areformer vessel 322 containing a supported ruthenium steam reformingcatalyst 324. The steam reforming reactions take place adiabatically asthe hydrocarbon-steam mixture passes through the catalyst 324. The hotreformed gas mixture is cooled in a heat exchanger 326 and one or morefurther heat exchangers (not shown) to below the dew point to generate acondensate/gas mixture, which is fed via line 328 to a first separator330. The condensed liquids are recovered via line 332 and the gases fedvia line 334 to a water-cooled heat exchanger 336 where they are furthercooled, and then to a second separator 338. The remaining condensate isrecovered from the separator 338 via line 340 and combined with thecondensate stream 332 from the first separator.

The combined condensate streams are fed to a condensate stripper 342. Awater feed stream 344 from the condensate stripper is mixed with make-upboiler feed water 346 and the combined water fed to the heat exchanger326 where it is heated in indirect heat exchange with the reformed gasmixture. A heated water/steam stream 348 from the heat exchanger 326 iscombined with a pumped re-circulated hot water stream 350 from thesaturator 318 and the combined water/steam mixture is further heated bypassing it through coils in the fired heater 308. The heated water/steamstream is then fed to the saturator 318 from the fired heater 308 vialine 352.

The de-watered reformed gas mixture recovered from the second separator338 is fed via pump 354 to acid gas recovery unit (AGRU) 356. Theacid-gas removal unit 356 contains a membrane that separates CO₂, and atleast part of the hydrogen and CO from the gas stream. The CO₂-richstream is recovered from the AGRU via line 358 In an alternativeembodiment, the acid-gas removal step uses an amine wash unit thatremoves the CO₂ and some H₂S by contacting the gas with an aqueous aminesolution. In yet a further alternative embodiment, the acid-gas removalstep uses a physical wash solvent unit that removes the CO₂ and some H₂Sby contacting the gas with refrigerated methanol, glycol, N-methylpyrrolidone or propylene carbonate.

The resulting methane gas stream is fed from the AGRU 356 via line 360to a drier vessel 362 where it contacts a zeolitic molecular sieve thatacts as a desiccant to remove water. The dried methane gas stream isthen recovered from the drier 362 via line 364. The dried gas may beused as a fuel directly or combined with a natural gas stream to adjustthe latter's composition and calorific value.

In FIG. 4, a natural gas feed stream 400 is passed at a temperaturebelow 100° C. and a pressure of about 10 bar abs, to a firstpurification vessel 402 containing a particulate copper-sulphide basedmercury absorbent 404. Mercury and other heavy metals such as arsenicare absorbed by the absorbent. The resulting gas stream is divided intotwo streams; a first stream 406 and a second stream 407. The firststream 406 is fed though coils in a fired heater 408 fuelled by naturalgas and/or higher hydrocarbon, where it is heated to a temperature about110° C. From fired heater 408 the gas is passed via line 410 to adesulphurisation vessel 412 containing a fixed bed of a particulate zincoxide desulphurisation absorbent 414 that removes hydrogen sulphidepresent in the gas. The desulphurised natural gas stream is passed fromthe desulphurisation vessel 412 via line 416, mixed with a hydrogenstream in line 417, and the mixture fed to a saturator 418 where it iscontacted with a stream of hot water/steam at a temperature about 190°C. and a pressure about 10 bar abs. The saturated hydrocarbon/steammixture is then fed at a temperature about 180° C. via line 420 to theinlet of a reformer vessel 422 containing a supported ruthenium steamreforming catalyst 424. The steam reforming reactions take placeadiabatically as the hydrocarbon-steam mixture passes through thecatalyst. The hot reformed gas mixture exits the reformer 422, is cooledin a heat exchanger 426 and one or more further heat exchangers (notshown) to below the dew point to generate a condensate/gas mixture,which is fed via line 428 to a first separator 430. The condensedliquids are recovered via line 432 and the gases fed via line 434 to awater-cooled heat exchanger 436 where they are further cooled beforebeing passed to a second separator 438. The remaining condensate isrecovered from the separator 438 via line 440 and combined with thecondensate stream 432 from the first separator.

The combined condensate streams are fed to a condensate stripper 442. Awater feed stream 444 from the condensate stripper is mixed with make-upboiler feed water 446 and the combined water fed to the heat exchanger426 where it is heated by the reformed gas mixture. A heated water/steamstream 448 from the heat exchanger 426 is combined with a pumpedre-circulated hot water stream 450 from the saturator 418 and thecombined water/steam mixture is further heated by passing it throughcoils in the fired heater 408. The heated water/steam stream is fed tothe saturator 418 from the fired heater 408 via line 452.

The de-watered reformed gas mixture 453 recovered from the secondseparator 438 is combined with the second stream of purified natural gas407 and fed via pump 454 to an acid gas recovery unit (AGRU) 456. Theacid-gas removal unit 456, contains a suitable membrane that separatescarbon dioxide, and at least part of the hydrogen and carbon monoxidefrom the gas stream. A carbon monoxide-rich stream is recovered from theAGRU via line 458 In an alternative embodiment, the acid-gas removalstep uses an amine wash unit that removes the carbon dioxide, hydrogen,carbon monoxide and some hydrogen sulphide by contacting the gas with anaqueous amine solution. In yet a further alternative embodiment, theacid-gas removal step uses a physical wash solvent unit that removes thecarbon dioxide, hydrogen, carbon monoxide and some hydrogen sulphide bycontacting the gas with refrigerated methanol, glycol, N-methylpyrrolidone, or propylene carbonate.

The resulting methane-enriched natural gas stream is fed from the AGRU456 via line 460 to a drier vessel 462 where it contacts a zeoliticmolecular sieve that acts as a desiccant to remove water. The dried gasstream is then cooled to between −20 and −40° C. in one or more heatexchangers 464 to form a liquefied natural gas stream 466, which isfractionated to produce ethane-, propane- and butane-rich streams. Ifdesired, at least a portion of the ethane stream may be vapourised andfed to line 406 (not shown).

In FIG. 5, a natural gas feed stream 500 is passed at a temperaturebelow 100° C. and a pressure in the range 10-100 bar abs, e.g. about 10bar abs, to a first purification vessel 502 containing a particulatecopper-sulphide based mercury absorbent 504. Mercury and other heavymetals such as arsenic are absorbed by the absorbent. The resultingpurified natural gas stream 506 is mixed with a de-watered reformed gasstream 508 and the resulting gas stream fed to an acid-gas removalvessel 510, containing a suitable membrane that separates CO₂ from thegas stream. In an alternative embodiment, the acid-gas removal step usesan amine wash unit that removes the CO₂ and some H₂S by contacting thegas with an aqueous amine solution. In yet a further alternativeembodiment, the acid-gas removal step uses a physical wash solvent unitthat removes the CO₂ and some H₂S by contacting the gas withrefrigerated methanol, glycol, N-methyl pyrrolidone, propylenecarbonate, or glycol ethers such as dimethyl ether of polyethyleneglycol.

The resulting CO₂-depleted gas stream 512, which may be described as amethane-enriched purified natural gas stream, is split into twoportions; a first portion 514 is combined with a higher hydrocarbonstream 516 and the combined stream fed via line 518 though coils in afired heater 520 fuelled by natural gas and/or higher hydrocarbon, whereit is heated to a temperature about 110° C. From fired heater 520 thegas is passed via line 522 to a desulphuriser vessel 524 containing afixed bed of a particulate zinc oxide desulphurisation absorbent 526that removes hydrogen sulphide present in the gas. The resultingdesulphurised natural gas stream is passed from the desulphuriser vessel524 vial line 528, mixed with a hydrogen stream in line 529 and themixture fed to a saturator 530 where it is contacted with a stream ofhot water/steam at a temperature about 190° C. at a pressure about 10bar abs. The saturated hydrocarbon/steam mixture is then fed at atemperature about 180° C. via line 532 to the inlet of a reformer vessel534 containing a supported ruthenium steam reforming catalyst 536. Thesteam reforming reactions take place adiabatically as thehydrocarbon-steam mixture passes through the catalyst. The hot reformedgas mixture is cooled in a heat exchanger 538 and one or more furtherheat exchangers (not shown) to below the dew point to generate acondensate/gas mixture, which is fed via line 540 to a first separator542. The condensed liquids are recovered via line 544 and the gases fedvia line 546 to a water-cooled heat exchanger 548 where they are furthercooled and then to a second separator 550. The remaining condensate isrecovered from the separator 550 via line 552 and combined with thecondensate stream 544 from the first separator.

The combined condensate streams are fed to a condensate stripper 554. Awater feed stream 556 from the condensate stripper is mixed with make-upboiler feed water 558 and the combined water fed to the heat exchanger538 where it is heated in indirect heat exchange with the reformed gasmixture. A heated water/steam stream 560 from the heat exchanger 538 iscombined with a pumped re-circulated hot water stream 562 from thesaturator 530 and the combined water/steam mixture is further heated bypassing it through coils in the fired heater 520. The heated water/steamstream is fed to the saturator 530 from the fired heater 520 via line564.

The de-watered reformed gas mixture recovered from the second separator550 is fed via line 508 to the purified natural gas stream 506 to formthe gas mixture fed to the acid gas recovery unit (AGRU) 510.

The remaining portion of the methane-enriched natural gas stream 512 isfed via line 566 to a drier vessel 568 where it contacts a zeoliticmolecular sieve that acts as a desiccant to remove water. The dried gasstream is then fed to a liquefaction and fractionation unit, where it isfirst cooled to between −20 and −40° C. In heat exchanger 570, whichcauses higher hydrocarbons to condense, and the resulting stream fed toa first fractionation column 572 where the higher hydrocarbons areseparated from a methane-rich stream. The condensates include heavycomponents such as benzene, cyclohexane, some propane and butane and C5+paraffins, and also some ethane and dissolved methane. The lightfraction 574 from the top of the column 572 is further cooled in heatexchanger 576 and condensed liquids separated in separator 578. Theseliquids are returned to the column 572 via line 580. The separated gasfrom separator 578 is then further cooled in heat exchanger 582 to forma liquefied natural gas 584. The higher hydrocarbon stream recoveredfrom column 572 is fed via line 586 to a second fractionation column 588(de-ethaniser) operated to recover an ethane-rich stream 590. The ethanestream 590 is vapourised in a vapouriser (not shown) and sent via line516 to be combined with the first portion of the methane-rich stream 514from the AGRU 310.

The mixed stream 592 recovered from the bottom of the secondfractionation column 588 is sent to a third column 594 (de-propaniser)where a propane-rich stream 596 is recovered. The mixed stream 598recovered from the bottom of the third fractionation column 594 is sentto a fourth column 600 (de-butaniser) where a butane-rich stream 602,and condensates stream 604 are recovered. The propane 596, butane 602and condensates 604 obtained from the de-propaniser 594 and debutaniser600 respectively may be sent for storage. If desired, a portion of thesestreams (shown by dotted lines) may be combined with the ethane stream590 and sent via line 516 to be used as part of the natural gas stream.

It will be understood that the above described liquefaction andfractionation unit may also be used in the embodiment depicted in FIG.4.

Furthermore, if desired, between drier 568 and heat exchanger 570, thepurified, CO₂-depleted and dried methane-enriched natural gas stream maybe passed through a preliminary separation unit (not shown) containing amembrane that separates a portion of the higher hydrocarbon from thenatural gas, thereby forming a gaseous higher hydrocarbon stream, whichis then fed to the higher hydrocarbon vapouriser.

In a further alternative embodiment, a portion of the purified naturalgas stream 506 from the purification vessel 502 may be combined with thehigher hydrocarbon stream 516 to form part of the natural gas stream fedto the reforming process. Moreover, it will be understood that where themercury content of the natural gas feed is negligible, purificationvessel 502 and sorbent 504 may be omitted. Similarly, where the CO₂content of the natural gas is negligible, the purified natural gasstream 506 may be directly combined with the higher hydrocarbon stream516.

EXAMPLES

The process of the present invention may be applied to so-called “rich”or “lean” natural gases. For example, natural gases that may besubjected to catalytic de-enrichment according to the present inventionmay have the following compositions:

1) LNG ex Marsa EI Braga Libya (Wobbe 53.26 MJ/m³)

Methane 83.68%

Ethane 11.73%

Propanes 3.51%

Butanes 0.28

Nitrogen 0.8%

2) LNG ex ADGAS UAE (Wobbe 53.48 MJ/m³)

Methane 84.0%

Ethane 14.0%

Propanes 1.0%

Butanes 0.9%

Nitrogen 0.1%

With this case, where the process is operated at a steam:carbon ratio(being the steam to higher hydrocarbon carbon ratio) of 2:1, thereformer inlet temperatures and reforming pressures are desirably asfollows;

Inlet Temperature (° C.) 150 230 250 Pressure (bar abs.) 10 70 100

3) Natural gas Methane 70% Ethane 15.0% Propanes 5.0% Butanes 5.0%Pentanes 2.0% Nitrogen 3.0%

With this case, where the process is operated at a steam:carbon ratio(being the steam to higher hydrocarbon carbon ratio) of 2:1, thereformer inlet temperatures and reforming pressures are desirably asfollows;

Inlet Temperature (° C.) 160 250 Pressure (bar abs.) 10 70

Alternatively the production of liquefied natural gas may be increasedby conversion of the natural gas liquids into methane. The followingtable shows the potential increase in LNG production using the processof the present invention.

Potential Increase Gas Composition (% vol) C1 C1 % Example C1 C2 C3 C4Amount Increase 1 100 — — — 100 0 2 95 5 — — 104 9 3 90 5 3 2 113 26 485 10 5 — 115 35

What is claimed:
 1. An apparatus for treating a natural gas streamcontaining methane and one or more higher hydrocarbon comprising: (i)means for adding steam and hydrogen to a natural gas stream, (ii) areformer vessel operatively connected to the means for adding steam andhydrogen, said reformer vessel containing a catalyst consisting of asupported precious metal reforming catalyst, configured such that thenatural gas stream, steam, and hydrogen are passed over the catalyst togenerate a reformed gas mixture comprising methane, steam, carbondioxide, carbon monoxide and hydrogen, (iii) heat exchange meansoperatively connected to the reformer vessel to cool the reformed gasmixture to below the dew point and separation equipment operativelyconnected to the heat exchange means to recover process condensate andprovide a de-watered reformed gas mixture, (iv) an acid gas recoveryunit operatively connected to the separation equipment to remove carbondioxide and at least a portion of the hydrogen and carbon monoxide,thereby generating a methane stream, and (v) a drying unit comprising abed of a solid desiccant or a liquid desiccant compound for drying themethane stream.
 2. The apparatus according to claim 1 further comprisinga natural gas liquefaction unit operatively connected to the acid gasrecovery unit to liquefy at least a portion of the methane stream. 3.The apparatus according to claim 1 forming part of an offshore naturalgas processing facility that is a fixed off-shore facility or a floatingoff-shore facility.
 4. The apparatus according to claim 1 comprisingmeans to supply at least one of natural gas, a synthetic natural gasmixture comprising methane, or one or more higher hydrocarbon to themeans for adding steam and hydrogen, wherein the natural gas comprisesat least one of associated gas, shale gas, tight sand gas, or coal bedmethane.
 5. The apparatus according to claim 1 comprising a purificationunit containing a purification material suitable for removing mercury,said unit installed upstream of the means for adding steam and hydrogen.6. The apparatus according to claim 1 further comprising a desulphuriservessel containing one or more purification material suitable forremoving a sulphur compound, said unit installed upstream of the meansfor adding steam and hydrogen.
 7. The apparatus according to claim 6comprising a fired heater through which is passed the natural gas streamand optionally a portion of the steam fed to the reformer vessel, saidheater installed upstream of said desulphuriser vessel.
 8. The apparatusaccording to claim 1 wherein the means for adding steam and hydrogencomprises a saturator.
 9. The apparatus according to claim 1 wherein thesteam reformer is an adiabatic steam reformer vessel containing asupported precious metal catalyst comprising 0.1-10% by weight of one ormore of Pt, Pd, Ir, Rh, or Ru.
 10. The apparatus according to claim 1further comprising one or more heat exchanger, configured to exchangeheat between the reformed gas mixture and water to generate at least aportion of the steam fed to the reformer vessel.
 11. The apparatusaccording to claim 1 wherein the separation equipment is operativelyconnected to the means for adding steam and hydrogen to the natural gasstream so that at least a portion of the recovered condensate is used togenerate at least a portion of the steam added to the natural gasstream.
 12. The apparatus according to claim 1 wherein the acid gasrecovery unit comprises at least one of a membrane, a physical washsolvent system, or an amine wash system.
 13. The apparatus according toclaim 1 further comprising a mixing unit configured to combine naturalgas with the de-watered reformed gas mixture or methane stream toprovide a methane-enriched natural gas.
 14. The apparatus according toclaim 1, wherein the heat exchange means is a heat exchanger.